1. Field of the Invention
This invention relates generally to oilfield equipment for monitoring and controlling wells that are produced by rod pumping where subsurface fluid pumps are driven via a rod string which is reciprocated by a pumping, unit located at the surface. The pumping unit may be of the predominate beam type or any other type that reciprocates the rod string.
In particular, this invention concerns using a down hole dynagraph, i.e., a pump card, with information as to the size of the down hole pump, to infer automatically the hydrocarbon production of the well.
Still more particularly, the invention concerns methods for use in a Well Monitor Controller where surface and pump cards are produced, whereby traditional well tests of a producing well can be eliminated.
2. Description of the Prior Art
Traditional Production Testing
A production test is a time-honored procedure in oil producing operations. It is involved in several activities including operation of the oilfield as a business venture, governmental regulation, well troubleshooting, and reserve estimates. With respect to its business role, it provides for division of leaseholder royalties and costs. To encourage prudent operation and enhance the stability of the nation, conservation authorities usually require periodic production tests. Also the production test is employed as a diagnostic indicator which calls attention to well problems that need to be addressed. It is important in reserve estimates, because cumulative production from each well needs to be known.
The use of the production test as a diagnostic indicator is perhaps the most recognized application among production specialists. A decline in production rate compared with a previous test can indicate a mechanical problem. The down hole pump may be worn or a tubing leak may have developed. The mechanical malfunction should be identified and remedied. The decline may also be caused by a change in reservoir conditions in the drainage area of the well. The receptivity of an offset injection well may have diminished. This may have resulted in a producing pressure decline and a decrease in production rate. The problem in the secondary recovery system should be rectified.
Conversely, an increase in productivity as measured by a well test may indicate that the well is responding to secondary recovery efforts. In this case, the well should be pumped more aggressively to obtain the increased production that is available.
The production test is a good tool for sensing that a change in the well has occurred, but it does not pinpoint the exact reason for the change. Usually a unique cause and effect relationship does not exist between a change in production rate and its cause. Because different causes may lead to the same effect, ambiguity exists. For example, a production decrease can have any number of causes such as a worn pump, a tubing leak, a failed tubing anchor, the onset of free gas production, secondary recovery deficiency, etc.
In the early years of the oil industry, each well had its own tankage and oil-gas-water separation equipment. The well was tested by measuring daily production into its tank. To decrease capital and operating costs, the handling and measurement system evolved into a centralized facility with flow lines extending from the individual wells. Production from the individual wells comes to a header. At the header a given well is placed either “on test” or has its production sent with that of other wells through a separate facility for separating and treating salable products. Ultimately the oil produced from the well(s) on test is combined with production from the remainder of the wells. The total production is then measured a final time and sold. The individual well test is used to determine the contribution of the subject well to total production from the lease 230. As mentioned previously, individual well tests are also used to equitably divide operating costs between the wells and to provide information for reserve estimates 230.
Meter malfunction is a significant problem for traditional production tests. In addition, the well test can be wrong even when the meters are working perfectly. Actual production is normally much lower than the test, primarily because of down time for equipment failures or other reasons. In principle, downtime is noted and accounted for, but down time measurement accuracy is poor. Downtime is often neglected entirely. The net effect is that traditional tests and actual production from individual wells can differ substantially, as much as from 10 to 20 percent. Accurately knowing actual production from each well is not only important for effective production operations but is also important for reservoir management 230.
Well test systems have evolved significantly. Automatically controlled diverting valves have replaced manual valves. Computers for scheduling well tests have been introduced. Significant improvements in the accuracy and reliability of measuring devices have also been made. Traditional production testing has come a long way since the pumper manually operated the system and recorded the results in an oily notebook with a stubby pencil.
Diagnostic Methods
As mentioned above, a production test has been used as a diagnostic tool to discover that a change has occurred in the well 230. The test itself does not point to the cause for the change. To determine specific cause(s) for change, diagnostic methods are employed. The best diagnostic methods are based on dynamometer analyses. Trial and error searches with the service rig (pulling unit) can also be used, but these searches are more costly to perform. Trial and error solutions require more time, and revenue is lost before the problem is identified.
Like the production test, a fluid level instrument is not capable of identifying the specific cause for a change. A change in fluid level can indicate several causes. If a relatively high fluid level is found, for example, the well operator only knows that the well is not producing at capacity. More investigation with diagnostic methods is required to identify the cause: it could be a worn pump, tubing leak, secondary recovery problem or something else.
Modern diagnostic analysis with the dynamometer began in the 1960's. The epochal development was the method for inferring the down hole pump card from surface dynamometer data. It was described in U.S. Pat. No. 3,343,409 (Gibbs). The down hole pump card (hereinafter called the “pump card”) was originally introduced in 1936. It was measured directly with a dynamometer located at the subsurface pump. The measured pump card had to be retrieved by a costly process of pulling the rods and pump. By 1960, computers were available which could solve the complicated equations required to calculate the pump card from data measured at the surface of the well. To produce the pump card 212, solutions to the wave equation are obtained which satisfy dynamometer time histories of surface rod load 208 and position 210.
Qualitative Evaluation of Down Hole Pump from the Shape of Pump Card
The pump card is very useful. Its shape reveals defective pumps, completely filled pumps, gassy or pounding wells, unanchored tubing, parted rods, etc. The pump card can also be used to compute producing pressure, liquid and gas throughput, and oil shrinkage effects. It can also be used to sense tubing leaks.
Quantitative Determination of Pump Leakage
Quantitative computation of pump leakage from pump cards was described in “Quantitative Determination of Rod-Pump. Leakage with Dynamometer Techniques”, Nolen, Gibbs, SPE Production Engineering, August 1990. Prior to this work, pump mechanical condition was obtained by (1) pulling the pump or (2) comparing the production test with estimates of pump capacity or (3) qualitative eyeballing of valve leakage rates measured with the dynamometer. The quantitative methods of Nolen and Gibbs to determine leakage involved use of scaled traveling or standing valve tests and information as to the manner in which the surface unit stops when turned off and information as to: the pump velocity measured from the pump card. These methods are discussed below in greater detail.
Pump Off Control Technology
Pump off control (POC) attained status as a viable method in the early 1970's. It was originally intended merely for stopping the well to prevent the mechanical damage of fluid pound and the power waste associated with operating an incompletely filled pump. From this humble beginning, the POC evolved into a distributed diagnostic system with well management capabilities 230. Gradually the phrase “pump off control” was replaced with terms like “Well Manager,” “Pump Rod Controller,” etc. (Lufkin Automation uses the trademark SAM to identify its Well Manager system). These new terms imply more than pump off control. The modern systems include diagnostic capability, collection and analysis of performance data and operation of the well in an economic fashion 230. The term WM is used below in this specification as an abbreviation for Well Manager of the type presently available through Lufkin Automation.
Over the years, POCs have used different algorithms to sense pump off. Some of these involve surface load change, motor current, motor speed, set points, dynamometer card area, and the down hole pump card. U.S. Pat. No. 5,252,031 to Gibbs describes pump off control through the use of “pump” cards. Because of its ability to sense liquid and gas throughput using the subsurface pump as a meter, POCs which use the pump card for control are desired for implementing Inferred Production (IP).
Inferred Production (IP) using a POC Well Manager (WM)
Current WMs infer production rate with considerable accuracy by using the subsurface pump as a flow meter. In other words inferred production (IP) can be determined without continuous use of traditional metering equipment. The current WM accumulates inferred fluid production with time and displays it for (1) manual recording and dissemination or (2) automatic transmittal to a central location via SCADA. A SCADA or telemetry system is helpful but not an absolute requirement. The WM always displays inferred production that can be retrieved during periodic visits by the pumper. However when a group of pumping wells is already under SCADA surveillance, IP is interfaced with SCADA for unattended telemetry of inferred production to a central collection point. The pump card based WM excels in the IP application over a SCADA produced pump card system. This is because the WM is monitoring its well continuously, stroke after stroke. The SCADA system can interrogate the well only a few times each day to retrieve dynamometer data. Therefore down hole or “pump” cards can be computed in SCADA only a few times each day. This causes errors in inferred production, particularly in wells where pump fillage varies rapidly.
Even in its incomplete state, the present system of gathering production data has the advantage of providing continuous well tests. This decreases the time lag between discovery and remediation of problems that affect production. Traditional well tests are often brief in duration (4 hours or less). In many cases these are not representative of true production rate. If the test system is serving a large number of wells, the traditional tests are infrequent, maybe only monthly. This acts to increase the time lapse between problem discovery and remediation.
It is important to identify the assumptions upon which a production test is inferred with a current prior art system.                1) The pump is in good mechanical condition and leakage is minimal.        2) The tubing is anchored at or near the pump.        3) Free gas volume in the pump is negligible at the time of traveling valve (TV) opening.        4) Oil shrinkage effects are negligible.        
FIG. 1 shows a typical rod pumping system, generally indicated by reference number 10, including a prime mover 12, typically an electric motor. The power output from the prime mover 12 is transmitted by a belt 14 to a gear box unit 16. The gear box unit 16 reduces the rotational speed generated by prime mover 12 and imparts a rotary motion to a pumping unit counterbalance, a counterweight 18, and to a crank arm 20 which is journaled to a crank shaft end 22 of gear box unit 16. The rotary motion of crank arm 20 is converted to reciprocating motion by means of a walking beam 24. Crank arm 20 is connected to walking beam 24 by means of a Pitman 26. A walking horsehead 28 and a cable 30 hang a polished rod 32 which extends through a stuffing box 34.
A rod string 36 of sucker rods hangs from polished rod 32 within a tubing 38 located in a casing 40. Tubing 38 can be held stationary to casing 40 by anchor 37. The rod string 36 is connected to a plunger 42 of a subsurface pump 44. Pump 44 includes a traveling valve 46, a standing valve 48 and a pump barrel 50. In a reciprocation cycle of the structure, including the walking beam 24, polished rod 32, rod string 36 and pump plunger 42, fluids are lifted on the upstroke. When pump fillage occurs on the upstroke between the traveling valve 46 and the standing valve 48, the fluid is trapped above the standing valve 48. A portion of this fluid is displaced above the traveling valve 46 when the traveling valve moves down. Then, this fluid is lifted toward the surface on the upstroke. A schematic description of pump valve operation is illustrated in FIGS. 2A and 2B.
As shown in FIG. 2A, when the rod string 36 is in an upstroke, the traveling valve 46 is closed and the fluid is lifted upward in the tubing 38. During the upstroke, fluid is drawn upward into the pump barrel 50 through the open standing valve 48. Referring to FIG. 2B for a description of the down stroke, as the plunger 42 is lowered, the traveling valve 46 is open thereby permitting fluid within the pump barrel 50 to pass through the valve to allow the plunger 42 to move downward. The fluid within the tubing 38 and the barrel 50 is held fixed in place by the closed standing valve 48. The rod string 36 does not carry any weight of fluid during the down stroke, but does lift the entire column of fluid during the upstroke.
A well manager unit 52 (see FIG. 1) receives or derives surface rod and load information 210, 208 (or equivalent measurements), draws a surface card and computes a pump card 212. Information about the subsurface pump 44, including surface and pump cards can be sent to a central location via telemetry equipment including antenna 54.
A current Inferred Production System can be described by reference to FIGS. 3 and 4. These Figures show traveling and standing valve action and the shape of typical pump cards that are computed by WM 52. FIG. 3E shows the familiar rectangular pump card shape 500 indicating full liquid fillage of the pump. FIG. 3F depicts a “fluid pound” card 510 showing incomplete liquid fillage. In both cases the pump is in good mechanical condition and the tubing is anchored near the pump. At low producing pressure, oil shrinkage effects and the volume of free gas at TV opening are negligible. Under pump off control, the pump normally fills completely with liquid for a time after startup. At a later time depending upon the well, pump fillage decreases and fluid pound develops. Eventually the WM 52 will stop the pumping unit 10 to prevent waste of power and the damaging effects of fluid pound. In FIG. 3E the gross stroke Sg and the net stroke Sn are shown. When the pump is filling completely with liquid, there is no free gas passing through the pump and Sn=Sg. The net liquid stroke is the distance traveled by the pump from TV opening (Point C) to the bottom of its stroke (Point D) FIG. 3E.
FIG. 3F represents the situation of an incompletely filled pump with a volume of liquid and low pressure free gas therein. At point B, the pump is at top of its stroke, and the standing valve (SV) has just closed. FIG. 3D. Later, on the down stroke (Point C) the traveling valve opens. The free gas has been compressed into a tiny volume that satisfies Assumption 3. The computer in the WM 52 is programmed to determine 214 when the traveling valve opens. Thus, the net liquid stroke is defined 232 with little error as the distance the pump travels from TV opening to the bottom of its stroke. See Sn in FIG. 3F.
In most cases the shut-down criterion for pump off control is based on liquid fillage of the pump. Fillage is defined as
                    Φ        =                              100            ⁢                                                  ⁢                          S              n                                            S            g                                              (        1        )            in which Θ is fillage percentage. The term fillage is defined by equation 1, and is commonly used and understood by practioners of rod pumping. The shut down percentage is chosen by the well technician and causes the WM 52 to stop the unit 10 when the calculated fillage drops below a preset value. For example a cut-off fillage of 90 percent causes the unit to shut down when liquid fillage drops below 90 percent of the full barrel volume. The digital computer in the WM is programmed to recognize when the traveling valve 46 opens, and this helps define the net liquid stroke Sn.
Using the Subsurface Pump as a Meter
The subsurface pump can be used as a meter to measure liquid and gas volumes. On a given stroke, the liquid volume (oil and water) passing through the pump is
                              Δ          ⁢                                          ⁢                      V            l                          =                              π            4                    ⁢                      d            2                    ⁢                      S            n                                              (        2        )            in which ΔV1 is measured in cubic inches and d is the diameter of the pump measured in inches. Equation 2 is the formula for computing the volume of a cylinder of diameter d and height Sn. If the unit 10 is turned off by the WM 52, the liquid volume isΔV1=0
The prior art WM 52 is programmed to obtain an estimate of liquid production passing through the pump in an interval of time. Stroke after stroke the WM derives the liquid stroke (i.e., Sn from FIG. 3E or 3F) from the pump card and computes the liquid volume from Equation (2). It accumulates (integrates) the liquid volumes during pumping strokes, whatever the fillage. The WM 52 has information when the unit 10 is stopped and no fluid is passing through the pump. The WM controls when the unit runs and when it is stopped. When 24 hours have passed, the WM 52 computes the inferred daily production rate RIP 228 in barrels per day from the elapsed time and accumulated volumes. This is expressed analytically as,
                              R          IP                =                  8.905          ⁢                                    ∑                                                          ⁢                              Δ                ⁢                                                                  ⁢                                  V                  l                                                                    (                                                T                  d                                +                                  T                  p                                            )                                                          (                  3          ⁢          a                )            in which Td and Tp are the accumulated downtimes and pumping times during the day, expressed in seconds. The coefficient 8.905 converts cubic inches per second into barrels per day. The integrated volume of liquid passing through the pump, stroke after stroke, is the sum, ΣΔV1.
Equation (3a) defines the prior art method for Inferred Production IP of liquids using the WM 52 or unit 10. Such equation, as described above, is based on assumptions of
(1) negligible pump leakage,
(2) anchored tubing,
(3) negligible free gas volume in pump at time of traveling valve (TV) opening, and
(4) oil shrinkage effects are negligible.
The prior art method for determining liquid volume daily production rate RIP (equation 3a) has been to provide a “k” factor to account for differences between measured production and inferred production using the pump as a meter. But when any of the basic assumptions above are not correct, the accuracy of the IP method decreases. The prior art “k” factor is
                    k        =                              R            t                                R            IP                                              (        4        )            in which Rt is the daily production rate measured in a traditional well test and RIP is the unadjusted inferred daily liquid rate. The k factor is multiplied by the unadjusted inferred daily liquid rate (determined from eq. 3a) to estimate the actual daily liquid rate of the well without actually measuring it by a traditional well test. The formula is,Rt=k RIP,  (5)where Rt is the adjusted value that is taken to be equivalent to the traditional well test. Ideally, the k factor is just below 1.0, for example in the range of 0.85 to 0.9. This factor accounts for the fact that the fundamental assumptions above are not always correct. All pumps leak, at least slightly. Tubing is not always anchored at or near the pump. A small volume of free gas is often present in the pump at the instant of traveling valve opening. If pressure in the pump is relatively high (the well is not completely pumped-off), the volume of free gas in the pump may not be small at all. Finally, most oil shrinks as gas evolves from it while passing up the tubing to the stock tank. Ideally the combined effect of these departures from the assumptions is small such that the k factor is slightly less than one as mentioned above.
The prior art method of using the subsurface pump as a meter for liquid volume inferred production (IP) is illustrated in the examples below.